1. Field of the Invention
This invention relates to servicing a wellbore. More specifically, it relates to the use of solid latex in wellbore servicing fluids.
2. Background of the Invention
Natural resources such as gas, oil, and water residing in a subterranean formation or zone are usually recovered by drilling a wellbore down to the subterranean formation while circulating a drilling fluid in the wellbore. After terminating the circulation of the drilling fluid, a string of pipe, e.g., casing, is run in the wellbore. The drilling fluid is then usually circulated downward through the interior of the pipe and upward through the annulus, which is located between the exterior of the pipe and the walls of the wellbore. Next, primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass (i.e., sheath) to thereby attach the string of pipe to the walls of the wellbore and seal the annulus. Subsequent secondary cementing operations may also be performed.
Fluids used in servicing a wellbore may be lost to the subterranean formation while circulating the fluids in the wellbore. These fluids may enter the subterranean formation via various types of leak-off flow paths in permeable zones such as depleted zones, zones of relatively low pressure, lost circulation zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the servicing fluid, and so forth. As a result, the service provided by such fluids is more difficult to achieve. Also, the loss of such fluids increases the cost of the overall operation due to the prolonged rig time required, the fluids being relatively expensive, and possibly a need to install additional casing.
There are a variety of methodologies for combating drilling fluid circulation losses. Such methodologies may involve adding loss prevention materials to the drilling fluid itself and continue the drilling process or pump fluid until fluid circulation is restored or may involve the use of a two-stream process. In a two-stream process, two fluid streams are introduced to the loss circulation area, for example by pumping one stream down the drillstring and one stream down the annulus, or alternatively via sequential pumping down the drillstring, annulus or both. These streams when mixed downhole near the loss circulation zones combine to rapidly form a viscous mass, which is designed to prevent further loss of drilling fluid into the fractures.
When such methods are successful in mitigating drilling fluid circulation losses, the operators have two options for follow-up operations. Their first option is to temporarily stop the drilling operation, case the well bore and cement the casing before resuming further drilling. This may result in a reduced well bore diameter from that point forward resulting in a smaller than planned pipe across the production intervals. During production, these reduced production pipe string diameters induce high friction pressures that restrict or limit production rates and negatively effect well production economics. This practice is adapted when the loss circulation sealant is not strong enough to withstand hydrostatic pressure of the drilling fluid if drilling is resumed without casing the well bore. The second option is more economical during the well construction phase and more profitable during the production phase. The second option involves using a loss circulation sealant that provides sufficient strength and reinforcement to the loss circulation zone so that it can withstand hydrostatic pressure from further drilling without resorting to casing the wellbore. This strengthening process is often referred to as increasing the Wellbore Pressure Containment Integrity (WPCI). This will not only save the cost of installing the extra casing or liner pipe strings, but it will also allow well completion with the planned well bore diameter that is required to achieve the expected production rates. In some cases, it will also lead to a wider than planned well bore diameter which after well completion and suitable stimulation operations, may facilitate increased production rates. The second option is a process referred to as a “Drill Ahead” process in the industry and in the later sections of this application. A “Drill Ahead” process and associated methods for introducing WPCI compositions into a wellbore to seal subterranean zones are described in U.S. Pat. No. 6,926,081B2, and in U.S. patent application Ser. No. 10/350,429 entitled “Methods of Improving Well Bore Pressure Containment Integrity” and filed on Jan. 24, 2003, which are incorporated by reference herein in their entirety.
Sealant compositions for use in fluid circulation losses may contain modifiers to enhance the mechanical properties of the sealant. Latex emulsions, which may contain a stable water-insoluble, polymeric colloidal suspension in an aqueous solution, are commonly used in sealant compositions to improve the properties of those compositions. For example, latex emulsions are used in cement compositions to reduce the loss of fluid there from and to reduce the cement's permeability to gas thereby substantially increasing the cement's resistance to gas flow from a gas-bearing formation. Latex emulsions are also employed to reduce the brittleness and improve the flexibility of sealant compositions; otherwise, the compositions may shatter under the impacts and shocks generated by drilling and other well operations. For example, with regard to fluid circulation loss, a two-stream process has been used where the first stream may be the drilling fluid itself or a designed fluid containing key ingredients while the second stream may comprise a latex emulsion. This process has found good commercial success in combating drilling fluid circulation losses especially in the case of oil-based muds (OBM).
The use of latex emulsions for combating drilling fluid circulation losses has some disadvantages. In the case of the two stream processes, preparing the latex-containing stream is operationally cumbersome and requires mixing an aqueous latex fluid, an aqueous stabilizing liquid surfactant and a dry solids blend prior to placing in a wellbore. This operation requires storage of two fluid components and a dry solid component. Also, there can be a substantial costs incurred for the shipping, storing and handling of latex emulsions. Furthermore, latex emulsions and the aqueous stabilizing surfactants present potential spill and leak related health, safety and environment (HSE) hazards. Frequently, it is operationally preferred and more cost effective to design cement slurries that use all solid components so that a single dry blend can be made in a bulk blending facility and transported to the field location where it is mixed with water prior to pumping. Use of aqueous latex emulsion requires more complex mixing operations.
Given the foregoing problems it would be desirable to develop a method of reducing the costs and HSE hazards associated with the use of latex in sealant compositions. Furthermore, it would be desirable to develop a method of preparing sealant compositions with latex that is operationally facile.